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A Norwegian Cinderella

Written by  Elaine Maslin Thursday, 01 June 2017 00:00

It took Norwegian fairy tale character Trestakk a few times to win her prince. Likewise, her oilfield namesake had to be put back on the shelf a few times before it could make the development grade. Elaine Maslin reports.

Trestakk subsurface layout. Image from Statoil.

Statoil’s Trestakk field has become so synonymous with its namesake – the Norwegian, Cinderella-like fairy tale character Kari Trestakk (“Katie Woodencloak”) – that those involved in the field even call the 76 MMboe field a “she.”

They’ve certainly had long enough to get to know her. Discovered in 1986, it wasn’t until 2015 that Statoil had a viable development concept on the table. Then there was a year of project optimization (reducing costs) required before Statoil could sanctioned and submitted a plan for development and operation (PDO) for Trestakk.

The result, outlined Håvard Stensrud, project director, Statoil, is a project with 50% reduced costs, a recovery rate 30% higher than initially thought, and 60% higher value (net present value). The field breakeven is also down more than half now, he told the Subsea Valley Conference in Oslo, early April. A true Cinderella story, indeed.

Lonely Trestakk

Trestakk, an oil field with some associated gas, was discovered and then appraised in 1986-7, on the Haltenbanken, in block 6406/3, in the Norwegian Sea, in about 300m water depth. The field, which sits 3900m beneath the seabed, is being developed as a 25km tieback to the Åsgard A production vessel, with a four-slot template and an attached single well satellite. Three of the wells will be producers, with two gas injectors, for reservoir support.

Statoil sanctioned the project last year – it’s largest project sanction in 2016 – and the PDO was approved early April 2017. The development is now in detailed design with fabrication expected to start this summer. All the main offshore operations will be in summer 2018, with drilling in the Fall, and first production in 2019.

“We have been struggling with Trestakk for a long time, not making it fly,” Stensrud says. “We share more with the fairy tale than just the name. It is a long story and it is the same with Trestakk. It’s about an underdog that never quits.”

When Trestakk was discovered, there was no other infrastructure on the Haltenbanken, Stensrud says, and it was thought to contain 50 MMboe, which didn’t support a full field development and platform. “We had to keep it in a drawer for a while,” he says.

In 1999, Åsgard A was brought on stream and then, towards 2010, Statoil started looking at Trestakk again, Stensrud says. Åsgard A was chosen as a host, but the facility was quite busy at the time, so the project didn’t play out. Then, the field was looked at again, including the possibility of developing it with Wintershall’s Maria field (due on stream in 2018, as a tieback drawing on four nearby facilities for services and export. (See OE: November 2016). It didn’t work out, however, due to economics, reservoir properties and other uncertainties, Stensrud says.

As more wells came on at Åsgard, however, more was learned about Trestakk and, early in 2015, Statoil set back concept select on Trestakk, believing it could “do it differently” and make it a commercial project.

Cost savings

The initial investment estimate for Trestakk was about US$1.17 billion (NOK10 billion), which was reduced to $820 million (NOK7 billion) when the concept selection was made in January 2016. Since then, additional improvements and concept adaptations reduced the estimate to about $640 million (NOK5.5 billion).  

Every element of the project was examined through 2016, Stensrud says. “We improved each part, sometimes beyond the targets we had set ourselves. This isn’t about taking advantage of the market going down and companies struggling. It’s about sustainable solutions.”

Cost savings were achieved through raw materials and rig rates, including shortened drilling time, optimized well strategy, and increased volumes in the development.

New, improved seismic was acquired to gain a better understanding of the reservoir and de-risk a segment of the field that is currently unproven. “The new seismic made us look more carefully to optimize well placement and gave us more confidence there are hydrocarbons [in the second segment] and de-risked that segment,” Stensrud adds. “We also have over the years increased our understanding of the regional trends, plus production data from other wells at Åsgard.”

The new seismic also helped reduce the number of pilot wells planned and optimize the wells and the well paths, reducing the number of meters needing to drilled – and therefore drilling days. Batch drilling was also looked at, and drilling and well services requirements were reduced to what was actually needed.

“We [also] looked at how we could be more efficient, having a standardized [tree and well] design, open hole completions, and standardized well solutions,” he says. Learnings from Statoil’s perfect well program will also be used.

Subsea layout

Another saving has been around the subsea layout and solutions, which was revisited and simplified towards concept selection, then further simplified when the Forsys joint venture (now TechnipFMC), came onboard for front-end engineering and design studies. The firm has since been contracted to supply the flexible riser, production flowline, gas injection line, flexible jumpers, and umbilicals for Trestakk, as well as the subsea production system — including subsea trees and completion system, a manifold, wellheads, subsea and topside control systems.

“One of the first thoughts (we had) was can we use the infrastructure at Åsgard better,” Stensrud asked. The system had included dynamic and static umbilicals. Changing the technical solution from connecting the umbilical to Åsgard A, and instead having a tie-in towards one of the existing templates nearby took out the dynamic umbilical and saved about 10km of static umbilical. Also, the original plan for two templates was simplified to one standard template and a satellite, so an additional gas injection line wasn’t needed.

More direct pipeline routing reduced scope and meant less seabed intervention. Laying the production line, umbilical and service line with inline Ts and flexible jumpers meant metrology and rigid spools could be cut out, saving about 40 days’ marine campaign, Stensrud says.

The vertical subsea tree and the template design are both a copy from Johan Sverdrup project, to reduce engineering hours.

Topsides

Further costs savings came from using existing and now available topside facilities and capacities on Åsgard, such as for the separators. In fact, Åsgard decided to move its low pressure wells to one separator so Trestakk fluids can be put through only the other separator, meaning a saving on metering and associated instrumentation and controls. The local equipment room, heating, ventilation and air conditioning, and hydraulic power unit scopes were also removed, because the timing was right to use capacity on Åsgard, Stensrud says.

Execute and repeat

Taking the lessons from Trestakk to make other existing and future discoveries near existing infrastructure could help the Norwegian shelf maintain its production levels, Stensrud says. “I don’t think Trestakk is unique. We have a lot of these fields near other infrastructure. The question is, can we use what we learned on Trestakk on other fields?”

It’s seen as an urgent issue on the Norwegian Continental Shelf, as in the UK North Sea, where existing infrastructure is now available, but may not be for much longer as producing fields deplete. The volumes from Trestakk will help Åsgard A keep running until at least 2030, which will also give time to maximize production from the field and give flexibility in the drainage strategy, Stensrud says. Without Trestakk, Åsgard A’s life could have been shorter and recovery less.

On Trestakk’s PDO submission, Kalmar Ildstad, the Norwegian Petroleum Directorate’s assistant director for development and operations in the Norwegian Sea, said: “The Norwegian Petroleum Directorate expects that all profitable projects are developed and that plans will take surrounding infrastructure into account.”

Statoil appears to be onboard. This year, four of Statoil’s Norwegian exploration discoveries have been near other installations, Stensrud says. Other, past, discoveries are also being looked at, to see how they can be made into further future Cinderellas.

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